Optical multiphase flowmeter

ABSTRACT

Method and apparatus enable direct measurement of at least one flow velocity for one or more phases within a multiphase fluid mixture flowing in a conduit. Some embodiments provide determination of actual individual phase flow rates for three phases (e.g., oil, water and gas) that are distinct from one another within the fluid mixture. A multiphase flowmeter according to embodiments of the invention includes at least two optical sensors spatially distributed along a length of the conduit and designed to detect light interactions with the fluid mixture unique to the phases such that detected time-varying signals can be processed via cross-correlation or an array processing algorithm to provide desired individual phase flow velocity for oil, water and/or gas phases. This flow velocity can be applied to phase fraction measurements, which can be obtained utilizing the same flowmeter or another separate device, to calculate the flow rates for the phases.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.11/421,700, filed Jun. 1, 2006 now U.S. Pat. No. 7,880,133, which isrelated to U.S. patent application Ser. No. 11/065,489 entitled“Multi-Channel Infrared Optical Phase Fraction Meter,” filed Feb. 24,2005, which are both herein incorporated by reference.

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the invention generally relate to methods and apparatusfor determining at least one flow velocity/rate for one or more phaseswithin a multiphase fluid flow.

2. Description of the Related Art

In the petroleum industry, as in many other industries, ability tomonitor flow of certain fluids in process pipes in real time offersconsiderable value. Oil and/or gas well operators periodically measurewater/oil/gas flow rates within an overall production flow streamcontaining a mixture of these three phases. This information aids inimproving well production, allocating royalties, properly inhibitingcorrosion based on the amount of water and generally determining thewell's performance.

While some techniques enable measuring flow rates within two phasemixtures, difficulty arises in determining individual volumetricfractions and flow rates in three phase mixtures. Separators can be usedto separate out one or more phases from the flow stream, but theyintroduce additional equipment and costs. Other costly and timeconsuming procedures entail manual sampling of the mixture to obtaininformation regarding the individual volumetric fractions. On the otherhand, flowmetering devices can be complex and can restrict flow creatingsignificant pressure loss, such as when venturi based measurements arerequired.

In many instances, multiphase flowmeters utilize a method to measure aflow rate of the entire flow stream and another process to measurevolume fractions of oil, water and gas. This measured information whenapplied to flow models enables estimation of each of the individualphase flow rates. However, the flow models make assumptions regardingthe flow characteristics such as by modeling with the flow model theslippage velocity between the liquid and gas phases. Therefore, the flowmodels cannot completely account for uniqueness of each particular fluidflow. In other words, application of these flow models with measuredtotal flow and volume fractions does not permit direct measurement ofactual phase velocities and flow rates independently.

Therefore, there exists a need for improved methods and apparatus thatenable determining at least one flow velocity for one or more phaseswithin a multiphase fluid flow and hence flow rate for the one or morephases.

SUMMARY OF THE INVENTION

Embodiments of the invention generally relate to methods and apparatusfor determining at least one flow velocity/rate for one or more phaseswithin a multiphase fluid flow. According to some embodiments, anapparatus for measuring flow of a fluid mixture in a conduit includesfirst and second optical sensors disposed along the conduit andconfigured to detect light interactions with the fluid mixture, whereinthe first optical sensor is separated by a distance in a direction offlow through the conduit from the second optical sensor, and a processorcoupled to receive first and second time-varying signals of the lightinteractions from the first and second optical sensors, respectively,wherein the processor is configured with logic to determine phasevelocity of at least one phase within the fluid mixture. In someembodiments, a method of measuring flow of a fluid mixture in a conduitincludes detecting light interactions with the fluid mixture at firstand second locations along the conduit, wherein the first location isseparated by a distance in a direction of flow through the conduit fromthe second location, and processing first and second time-varyingsignals of the light interactions detected at the first and secondlocations, respectively, wherein the processing determines phasevelocity of at least one phase within the fluid mixture. For someembodiments, a method of measuring flow of a fluid mixture in a conduitincludes measuring light interactions at first and second locationsalong the conduit to detect a time delay in interactions detected at thefirst location and then the second, and calculating a velocity of flowwithin the fluid mixture based on the time delay.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the presentinvention can be understood in detail, a more particular description ofthe invention, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlytypical embodiments of this invention and are therefore not to beconsidered limiting of its scope, for the invention may admit to otherequally effective embodiments.

FIG. 1 is a schematic sectional view across a length of conduit having afluid mixture flowing therein and first and second optical sensingdevices spaced along the length, according to embodiments of theinvention.

FIG. 2 is a graph illustrating absorption of two types of oil, water andcondensate for an infrared region and selected wavelengths, which can beselected for interrogation via the sensing devices shown in FIG. 1.

FIG. 3 is a diagram of a distributed array of the optical sensingdevices coupled to logic configured to enable calculation of at leastone flow velocity of one or more phases within the mixture based ondetermining a time delay from one sensor to another of certaintime-varying properties detected at various wavelengths, according toembodiments of the invention.

FIG. 4 is a graph of signals detected from the first and seconddetectors versus time illustrating the time delay (τ).

FIG. 5 is a schematic sectional view of first and second reflectancebased optical sensing devices for use with some embodiments in similarapplications as utilized with transmittance detectors shown in FIGS. 1and 3.

FIG. 6 is a schematic view of first and second attenuated totalreflection and/or refractive index based optical sensing devices for usewith some embodiments according to techniques such as applied withtransmittance detectors shown in FIGS. 1 and 3.

DETAILED DESCRIPTION

Embodiments of the invention relate to methods and apparatus that enabledirect measurement of at least one flow velocity for one or more phases,individually or in combination, within a multiphase fluid mixtureflowing in a conduit. Some embodiments provide determination of actualindividual phase flow rates for each of three phases (e.g., oil, waterand gas) that are distinct from one another within the fluid mixture. Amultiphase flowmeter according to embodiments of the invention includesat least two optical sensors spatially distributed along a length of theconduit and designed to detect light interactions with the fluid mixtureunique to the phases such that detected time-varying signals can beprocessed via cross-correlation or an array processing algorithm toprovide desired individual phase flow velocity for oil, water and/or gasphases. This flow velocity can be applied to phase fractionmeasurements, which can be obtained utilizing the same flowmeter oranother separate device, to calculate the flow rates for the phases.

FIG. 1 shows a length of conduit 100 having a first optical sensingdevice 104 and a second optical sensing device 106 spaced along thelength. A fluid flow 101 indicated by an arrow travels through theconduit and can include a water phase 108, an oil phase 110 and a gasphase 112. The water, oil and gas phases 108, 110, 112 remain distinctfrom one another regardless of various possible flow patterns of thismixture such as a depicted exemplary flow pattern of the phases.

The first optical sensing device 104 includes a first source 311 forintroducing light (indicated throughout by arrows 150) into the fluidflow 101 and a first detector 301 to detect the light after beingtransmitted through the fluid flow 101. Similarly, the second opticalsensing device 106 includes a second source 312 for introducing lightinto the fluid flow 101 and a second detector 302 to detect the lightafter being transmitted through the fluid flow 101. Windows 103 withinthe wall of the conduit 100 enable passing the light from each of thesources 311, 312 to corresponding ones of the detectors 301, 302 acrossthe fluid flow 101. Other than being disposed at different locations,the sensing devices 104, 106 can be identical. For some embodiments, thedevices 104, 106, individually or collectively, may be the same orsimilar to one or more of those described in U.S. patent applicationSer. No. 11/065,489 (hereinafter referred to as the '489 application)previously incorporated by reference.

The sources 311, 312 can originate from a single emitter that is splitor from separate emitters. Further, the sources 311, 312 can includebroadband light emitters or one or more narrow band lasers. Each of thephases 108, 110, 112 attenuate the light differently for variouswavelengths as the light passes through the fluid flow 101. Accordingly,the detectors 301, 302 measure the light transmitted through the fluidflow 101 for particular individual wavelengths that correspond to thewater, oil and gas phases 108, 110, 112. Depending on the sources 311,312 utilized, appropriate filters coupled with the sources 311, 312and/or the detectors 301, 302 can discriminate for desired wavelengths.

A communication line 114 coupled to the detectors 301, 302 conveyssignals regarding this attenuation of certain wavelengths to processingequipment that analyzes the signals with a cross-correlation or arrayprocessing algorithm as described further below. As the basis of thisanalysis, the water phase 108, for example, within a cross section ofthe fluid flow 101 at a location of the first sensing device 104 has aunique percentage of the flow, distribution or other property at a giventime such that selecting wavelengths for water phase analyses enablesdetecting the same event of the water phase 108 at a later instant intime with the second sensing device 106 once the fluid flow 101progresses toward the second sensing device 106. A corresponding analogyapplies for the oil phase 110 and the gas phase 112.

Any particular aspect of the fluid flow tends to change or dissipate tosome degree as that aspect moves with the fluid flow 101 depending onthe coherence of the fluid flow. Advantageously, little appreciablechange in the fluid flow 101 occurs between the sensing devices 104, 106due to selection of spacing between the sensing devices 104, 106.Further, the sensing devices 104, 106 sample at intervals such asseveral hertz to several kilohertz to provide a depiction of a discretecross section of the flow without significant averaging of the fluidflow 101 over time, which would tend to obscure time-varying responsesto be compared.

Once the time-varying signal(s) is measured for any desired phaseswithin the fluid flow 101, a time delay (τ) can be measured usingcross-correlation methods. Velocity of flow for each phases is thereforecalculated as being a distance between the sensing devices 104, 106divided by the time delay (V=x/τ). Alternatively, the flow velocity canbe calculated using an array processing algorithm. As mentioned above,differentiation between the phases 108, 110, 112 occurs by thetime-varying signal(s) being selected such that it corresponds to one ofthe phases through, for example, a ratio between two wavelengthsdetected or one wavelength detected by itself. Attenuation of onewavelength may be substantially dependent on (i.e., sensitive to) afirst phase and substantially independent of (i.e., substantiallyinsensitive to) a second phase, while attenuation of another wavelengthmay be substantially independent of the first phase and substantiallydependent on the second phase. A first wavelength band emitted by thesources 311, 312 can be substantially transmitted through a first phase(e.g., the water phase 108) of the fluid flow 101 and substantiallyabsorbed by a second phase (e.g., the oil phase 110), and a secondwavelength band emitted by the sources 311, 312 can be substantiallyabsorbed by the first phase relative to the second phase. The detectors301, 302 can detect attenuation of the first and second wavelength bandsupon the infrared radiation passing through at least a portion of thefluid flow 101 such that the time delay τ is determined based on theattenuation of both the first and second wavelength bands.

FIG. 2 illustrates a graph of absorption versus wavelength for two typesof oil indicated by curves 501, 502, water represented by curve 503 andcondensate denoted by curve 504 for an infrared region. The graph showsfour wavelength bands 505-508 for filtering/analysis in determining flowvelocities according to embodiments of the invention. Other wavelengthbands may be selected without departing from the scope of the invention.In general, a first wavelength band 505 includes wavelengths within arange of approximately 900 nanometers (nm) to 1200 nm, for example about950 nm, where there is an oil absorbent peak. A second wavelength band506 includes wavelengths centered around 1450 nm where there is a waterabsorbent peak. A trough around 1650 nm provides another interrogationregion where a third wavelength band 507 generally is centered. A fourthwavelength band 508 generally includes a peak centered about 1730 nmthat is fundamentally associated with carbon-hydrogen bonds of the oil501, 502 and the condensate 504. The substantial similarities and/ordifferences in the absorbance of the different phases 108, 110, 112 ateach of the bands 505-508 further enables their differentiation from oneanother.

FIG. 3 shows a diagram of a flowmeter system 300 utilizing the sources311, 312 and detectors 301, 302 forming a distributed array 304. Thearray 304 can include additional sensors and detectors 305, which may beidentical or configured to provide different wavelength analysis and/ordifferent spacing. Each detector 301, 302 measures transmittance toprovide as output a first wavelength (λ₁) signal 314, a secondwavelength (λ₂) signal 316 and any additional wavelength (λ_(N))signals. Cross-correlation logic 317 determines the time delay (τ)associated with each of the wavelength signals detected at the detectors301, 302 as a result of the spacing within the array 304 as indicated bythe distance x.

FIG. 4 shows a graph of a first detected transmittance 401 measured withthe first detector along with a second detected transmittance 402measured by the second detector versus time illustrating the time delayτ between the detected transmittances 401, 402. The detectedtransmittances 401, 402 represent transmittance of the first wavelengthλ₁ signal 314. For example, the first wavelength λ₁ can be at 1450 nmsuch that the time delay τ corresponds to the time required for waterwithin the fluid flow 101 to travel the distance x. For someembodiments, the wavelength signals can be based on a particularwavelength(s) or a ratio of signals from two or more wavelength(s) inview of unique absorption characteristics of phases within the fluidflow 101 such as described above relating to FIG. 2. As examples of thisratio, one wavelength can be selected that is sensitive to gas forcomparison with another wavelength selected that is insensitive to gasor other wavelengths sensitive to other constituents of the fluid flow101.

As illustrated in FIG. 3, flow logic 318 receives input from thecross-correlation logic 317 and provides a flow velocity/rate of atleast one of the water, oil and/or gas phases 108, 110, 112,individually or in combination, via an output 320 in the form of adisplay, printout or other user interface. The flow logic 318 cancalculate the velocity (V) for each phase given the distance x and thetime delay τ with the formula V=x/τ. As described in the '489application, the phase fraction of the water, oil and/or gas phases 108,110, 112 can be calculated. By configuring the array 304 to determinephase fractions as described in the '489 application or utilizing anyseparate phase fraction meter such as described in the '489 application,individual flow rates for the water, oil and/or gas phases 108, 110, 112can hence be calculated based on application of respective flowvelocities to these phase fractions.

FIG. 5 shows a schematic sectional view of first and second reflectancebased optical sensing devices 204, 206 for use with some embodiments. Insimilar applications as utilized with transmittance detectors shown inFIGS. 1 and 3, the reflectance based optical sensing devices 204, 206enable flow velocity/rate determinations. Analogous processingtechniques to those previously described herein can be applied toreflected light detected, which is unique to water, oil and gas phases208, 210, 212. In operation, light emitted by first and second sources211, 213 reflects off of the water, oil and gas phases 208, 210, 212 andthis reflected light is detected at first and second detectors 201, 202,respectively, with certain reflected wavelengths associated with eachphase. A time delay τ occurs with the detected reflected light fortime-varying reflectance based phenomena traveling with the fluid flow.Therefore, velocity can be calculated as a function of distance betweenthe reflectance based optical sensing devices 204, 206 and time it takesto detect a reflected light feature with the second detector 202 afterbeing detected at the first detector 201. Further, velocity fordifferent ones or combinations of the phases 208, 210, 212 can becalculated depending on which phase(s) the reflected light featurecorresponds to given the wavelength(s) measured at the detectors 201,202.

FIG. 6 illustrates a schematic sectional view of first and secondrefractometers 604, 606 for use with some embodiments. Therefractometers 604, 606 can enable refractometry and attenuated totalreflectance (ATR) spectrometry by measuring the refractive index offluids and/or attenuated reflectance spectra. A fluid flow 601 exposedat windows 603 to first and second light sources 611, 613 disposed at anangle with respect to correspondingly angled detectors 610, 612 providesvarying refractive indices based on constituents of the fluid flow 601.The windows 603 have a refractive index of about 1.7, for example, suchthat light transmitted through the windows reflects at an interfacebetween the window 603 and the fluid flow 601 due to differences in therefractive indices of the windows and the fluid flow. Further, somelight is absorbed by the constituents of the fluid flow 601 at thisinterface such that attenuation characteristics of the light reflecteddiffers depending on absorbency of these constituents. While the windows603 in this and other illustrated embodiments are shown separate, someembodiments can integrate the windows utilizing a single window for morethan one sensing device such as the refractometers 604, 606. Thedetectors 610, 612 measure increases in reflections such as when therefractive index of the fluid flow 601 decreases. An oil phase having arefractive index of about 1.5 gives rise to a reflected fraction oflight from the sources 611, 613 which, for example, is less than 20%.However, a water fraction with a refractive index typically in the range1.3 to 1.4 produces a reflected fraction of the light that is about30-65% while gas with a refractive index close to 1.0 provides areflected fraction of the light approaching 100%.

Time-varying signals within corresponding strengths of reflected signalsdetected for the different phases can be determined by analyzingresponses from the first and second detectors 610, 612. Respective timedelays occur with the detected reflected light for these strengths ofthe reflected signals enabling differentiation of a time delay τ foreach phase. Therefore, velocity can be calculated as a function ofdistance between the refractometers 604, 606 and time it takes to detecta refractive index characteristic of one phase at the second detector612 after being detected at the first detector 610.

Embodiments illustrated provide non-intrusive flow velocity/rateanalysis techniques. For example, the first source 311 is disposedoutside the conduit 100 and opposite the first detector 301 also locatedoutside the conduit such that the transmission or absorptionmeasurements are full-bore across a cross section of the conduit 100.Some embodiments however can be implemented as an intrusive probe asillustrated, for example, in the '489 application previouslyincorporated by reference.

While the foregoing is directed to embodiments of the present invention,other and further embodiments of the invention may be devised withoutdeparting from the basic scope thereof, and the scope thereof isdetermined by the claims that follow.

What is claimed is:
 1. An apparatus for measuring flow of a fluidmixture in a conduit, comprising: at least one light source fortransmitting light into the fluid mixture; first and second opticalsensors disposed along the conduit and configured to detect lightinteractions with the fluid mixture, wherein the first optical sensor isseparated by a distance in a direction of flow through the conduit fromthe second optical sensor, wherein the light interactions detected bythe optical sensors are a measure of reflectance of the lighttransmitted into the fluid mixture, and wherein the light source is on asame side of the conduit as the first and second optical sensors; and aprocessor coupled to receive first and second time-varying signals ofthe light interactions from the first and second optical sensors,respectively, wherein the processor is configured with logic todetermine phase velocity of at least one phase within the fluid mixture.2. The apparatus of claim 1, wherein the logic calculates a time delayof corresponding responses within the first and second time-varyingsignals.
 3. The apparatus of claim 1, wherein the logic determines thephase velocity based on the distance divided by the time delay.
 4. Theapparatus of claim 1, wherein the optical sensors form refractometers.5. The apparatus of claim 1, wherein each of the sensors is disposednon-intrusively outside of the conduit.
 6. The apparatus of claim 1,wherein the logic is further configured to determine individual phasevelocities for each of three distinct phases within the fluid mixture.7. The apparatus of claim 1, wherein the first and second time-varyingsignals correspond to wavelength signals selectively responsive to theat least one phase.
 8. The apparatus of claim 1, wherein the logic isfurther configured to determine phase flow rate of the at least onephase given a phase fraction of the at least one phase.
 9. The apparatusof claim 1, wherein the logic comprises a cross-correlation algorithm.10. The apparatus of claim 1, wherein: the light source is configured toemit into the fluid mixture infrared radiation that includes at leastfirst and second wavelength bands, the first wavelength bandsubstantially transmitted through a first phase of the fluid mixture andsubstantially absorbed by a second phase, and the second wavelength bandsubstantially absorbed by the first phase relative to the second phase;and at least one of the first and second optical sensors is configuredto provide the time varying signals based on detection of attenuation ofthe first and second wavelength bands upon the infrared radiationpassing through at least a portion of the fluid mixture.
 11. A method ofmeasuring flow of a fluid mixture in a conduit, comprising: transmittinglight into the fluid mixture; detecting light interactions with thefluid mixture at first and second locations along the conduit, whereinthe first location is separated by a distance in a direction of flowthrough the conduit from the second location, wherein the light istransmitted into the fluid mixture on a same side of the conduit as thefirst and second locations, and wherein the light interactions detectedat the first and second locations are a measure of reflectance of thelight transmitted into the fluid mixture; and processing first andsecond time-varying signals of the light interactions detected at thefirst and second locations, respectively, wherein the processingdetermines phase velocity of at least one phase within the fluidmixture.
 12. The method of claim 11, wherein the processing comprisescalculating a time delay of corresponding responses within the first andsecond time-varying signals.
 13. The method of claim 12, wherein theprocessing determines the phase velocity based on the distance dividedby the time delay.
 14. The method of claim 11, wherein the processingdetermines individual phase velocities for each of three distinct phaseswithin the fluid mixture.
 15. The method of claim 11, wherein thedetecting the light interactions comprises measuring reflectance oflight transmitted into the fluid mixture to provide the first and secondtime-varying signals corresponding to wavelength signals selectivelyresponsive to the at least one phase.
 16. The method of claim 11,further comprising: determining a phase fraction of the at least onephase; and calculating a phase flow rate of the at least one phaseutilizing the phase velocity and the phase fraction as determined.
 17. Amethod of measuring flow of a fluid mixture in a conduit, comprising:transmitting light into the fluid mixture; measuring light interactionsat first and second locations along the conduit to detect a time delayin interactions detected at the first location and then the second,wherein the light is transmitted into the fluid mixture on a same sideof the conduit as the first and second locations and wherein the lightinteractions detected are a measure of reflectance of light transmittedinto the fluid mixture; and calculating a velocity of flow within thefluid mixture based on the time delay.
 18. The method of claim 17,further comprising: determining a phase fraction within the fluidmixture; and calculating a phase flow rate utilizing the velocity andthe phase fraction.